As modern CMOS circuits fabricated with advanced technology nodes are becoming more and more susceptible to soft-errors, many hardened latches have been proposed for reliable LSI designs. We reveal for the first time that production defects in such hardened latches can cause two serious problems: (1) these production defects are difficult to detect with conventional scan test and (2) these production defects can reduce the reliability of hardened latches. This paper systematically addresses these two problems with three major contributions: (1) Post-Test Vulnerability Factor (PTVF), a first-of-its-kind metric for quantifying the impact of production defects on hardened latches, (2) a novel Scan-Test-Aware Hardened Latch (STAHL) design that has the highest defect coverage compared to state-of-the-art hardened latch designs, and (3) an STAHL-based scan test procedure. Comprehensive simulation results demonstrate the accuracy of the proposed PTVF metric and the effectiveness of the STAHL-based scan test. As the first comprehensive study bridging the gap between hardened latch design and LSI testing, the findings of this paper will significantly improve the soft-error-related reliability of LSI designs for safety-critical applications.

In recent years, fracturing-flooding technology has achieved a series of successful practices in the development of low-permeability oil reservoirs. However, research on the dynamic behavior of fracturing-flooding remains limited. In this paper, a dual medium model considering anisotropic characteristics is established for the target blocks. Multiple sets of conventional water injection transitions and multi-cycle fracturing-flooding operations are designed for simulation to explore the subsequent optimal operational schemes. Simulations are conducted on the optimal transitions between conventional water injection and multi-cycle fracturing-flooding schemes for different reservoir models with varying physical properties to study the dynamic behavior of fracturing-flooding in oil reservoirs with different properties. The results indicate that, for conventional water injection schemes, the optimal transition time for both the target well group and other reservoirs with different properties corresponds to a formation pressure coefficient between 1.2 and 1.3, with the optimal injection–production ratio being 1:1. From the perspective of water cut, the accumulated oil production of multi-cycle fracturing-flooding is higher than that of conventional water injection. The optimal multi-cycle fracturing-flooding schemes for both the target well group and other reservoirs with different properties are to start fracturing-flooding when the formation pressure coefficient is around 0.8 and to begin production when it reaches 1.4.

In the process of long-term water flooding in the Gaoqian Southern Area with an average porosity of 30% and an average permeability of μm², the fluid-solid interaction among oil, water, and rock has a great influence on the pore structure. It has resulted in changes in reservoir parameters with the extension of time. This paper used electron microscopy scanning, mercury injection, X-ray diffraction, physical properties, and oil-water relative permeability curves to study the variation of clay mineral content, pore throat structure, porosity, permeability, and relative permeability curves of high-permeability sandstone after high-pressure water flooding. The results showed that clay minerals such as montmorillonite and kaolinite were dissolved, hydrated, and migrated after long-term water flooding, which resulted in the decrease of clay mineral content in fine sandstone and medium sandstone, the increase of pore throat radius, and the decrease of displacement pressure, median pressure, and separation coefficient. The saturation of the isotonic point of the oil-water relative permeability curve was obviously shifted to the right, the hydrophilicity was significantly enhanced, and the porosity and permeability were effectively improved, but there was a blockage of the throat less than 2 μm in the fine sandstone. In addition, this paper established the equations of water injection, permeability, irreducible water saturation, residual oil saturation, and oil-water relative permeability curve coefficient and establishes the initial permeability model with the well data before water flooding. The logging interpretation results of development wells in the process of water flooding as verification data were used, and the relative error of permeability far lower than the general requirement of permeability error within an order of magnitude was less than 30%, which verified the rationality of the method.

The low permeability and submicron throats in most shale or tight sandstone reservoirs have a significant impact on microscale flow. The flow characteristics can be described with difficultly by the conventional Darcy flow in low-permeability reservoirs. In particular, the thickness of the boundary layer is an important factor affecting the formation permeability, and the relative permeability curve obtained under conventional conditions cannot accurately express the seepage characteristics of porous media. In this work, the apparent permeability and relative permeability were calculated by using non-Darcy-flow mathematical modeling. The results revealed that the newly calculated oil–water relative permeability was slightly higher than that calculated by the Darcy seepage model. The results of the non-Darcy flow based on the conceptual model showed that the area swept by water in non-Darcy was smaller than that in Darcy seepage. The fingering phenomenon and the high bottom hole pressure in the non-Darcy seepage model resulted from the larger amount of injected water. There was a large pressure difference between the injection and production wells where the permeability changed greatly. A small pressure difference between wells resulted in lower variation of permeability. Consequently, the non-Darcy simulation results were consistent with actual production data.

As a core part of the refined description of multilayer gas reservoirs, it is difficult for existing methods to quantify the dynamic effects of fluid flow or interference due to interlayer pressure differences in multilayer gas reservoir. In this paper, we propose a new production splitting method based on the principle of superposition of potentials combined with the particle swarm optimization (PSO) algorithm, which aims to better fit the dynamic nature of reservoir fluid flow. The study firstly constructs a three-dimensional spatio-temporal effect fluid potential mathematical model based on the principle of superposition of potentials, and proposes a new method of gas well production splitting based on the principle of superposition of potentials by coupling the potential field calculation of each layer. The results show that the model constructed based on the superposition of potentials has high accuracy, overcomes the discontinuity of the traditional splitting method and the problem of quantifying the interlayer interference, and can dynamically and continuously realize the accurate splitting of the production of each sand body in multilayered collocated gas reservoirs; based on the RFT layered pressure measurement data, the pressure prediction model constructed by ridge regression computes the pressure of the sand body at different times more accurately, and the correlation with the dynamic reserves is good. By taking Sebei No.2 gas field 2 − 1 layer group well Se 5-1-2 as an example for application analysis, it is found that the relative error between the splitting coefficient and the gas production profile data is basically less than 10%, and the error of individual low-production layers is slightly larger; the correlation analysis of dynamic reserves and pressure coefficient of four sands shows that the error of the dynamic reserves calculated based on the method is only 3.82% from the results of the flow pressure calculations. Compared with 106 static pressure test results, the error is less than 10%.